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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(MARK ONE)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission File Number 33-38511
SOUTHWEST DEVELOPMENTAL DRILLING PROGRAM 1991-92
Southwest Developmental Drilling Fund 91-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2387814
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
Midland, Texas 79701
(Address of principal executive offices)
(915) 686-9927
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes X No
The total number of pages contained in this report is 17.
<PAGE>
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the notes thereto for
the year ended December 31, 1998 which are found in the Registrant's Form
10-K Report for 1998 filed with the Securities and Exchange Commission.
The December 31, 1998 balance sheet included herein has been taken from the
Registrant's 1998 Form 10-K Report. Operating results for the three and
six month periods ended June 30, 1999 are not necessarily indicative of the
results that may be expected for the full year.
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Balance Sheets
June 30, December 31,
1999 1998
--------- ------------
(unaudited)
Assets
Current assets:
Cash and cash equivalents $ 8,278 10,719
Receivable from Managing General Partner 20,274 241
--------- ---------
Total current assets 28,552 10,960
--------- ---------
Oil and gas properties - using the
full cost method of accounting 1,098,374 1,097,568
Less accumulated depreciation,
depletion and amortization 924,600 913,000
--------- ---------
Net oil and gas properties 173,774 184,568
--------- ---------
$ 202,326 195,528
========= =========
Liabilities and Partners' Equity
Current liability - Distribution payable $ 522 2,630
--------- ---------
Partners' equity:
Managing General Partner 23,967 21,711
Investor partners 177,837 171,187
--------- ---------
Total partners' equity 201,804 192,898
--------- ---------
$ 202,326 195,528
========= =========
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
Revenues
Oil and gas $ 45,273 42,382 84,444 92,616
Interest 44 80 56 101
------- ------- ------- -------
45,317 42,462 84,500 92,717
------- ------- ------- -------
Expenses
Production 17,730 31,256 35,065 49,767
General and administrative 4,427 5,730 8,929 15,300
Depreciation, depletion and
amortization 4,600 12,000 11,600 24,000
------- ------- ------- -------
26,757 48,986 55,594 89,067
------- ------- ------- -------
Net income (loss) $ 18,560 (6,524) 28,906 3,650
======= ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 2,548 602 4,456 3,041
======= ======= ======= =======
Investor partners $ 16,012 (7,126) 24,450 609
======= ======= ======= =======
Per investor partner unit $ 13.99 (6.23) 21.36 .53
======= ======= ======= =======
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows
(unaudited)
Six Months Ended
June 30,
1999 1998
Cash flows from operating activities:
Cash received from oil and gas sales $ 68,596 106,139
Cash paid to suppliers (48,179) (65,341)
Interest received 56 101
------- --------
Net cash provided by operating activities 20,473 40,899
------- --------
Cash flows used in investing activities:
Additions of oil and gas properties (806) (20,739)
------- --------
Cash flows used in financing activities:
Distributions to partners (22,108) (17,927)
------- --------
Net increase (decrease) in cash and cash equivalents (2,441) 2,233
Beginning of period 10,719 3,477
------- --------
End of period $ 8,278 5,710
======= ========
(continued)
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
Statements of Cash Flows, continued
(unaudited)
Six Months Ended
June 30,
1999 1998
Reconciliation of net income to net
cash provided by operating activities:
Net income $ 28,906 3,650
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 11,600 24,000
(Increase) decrease in receivables (15,848) 13,523
Decrease in payables (4,185) (274)
------- -------
Net cash provided by operating activities $ 20,473 40,899
======= =======
<PAGE>
Southwest Developmental Drilling Fund 91-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Developmental Drilling Fund 91-A, L.P. was organized under
the laws of the state of Delaware on January 7, 1991 for the purpose
of drilling developmental and exploratory wells and to produce and
market crude oil and natural gas produced from such properties for a
term of 50 years, unless terminated at an earlier date as provided for
in the Partnership Agreement. The Partnership sells its oil and gas
production to a variety of purchasers with the prices it receives
being dependent upon the oil and gas economy. Southwest Royalties,
Inc. serves as the Managing General Partner. Revenues, costs and
expenses are allocated as follows:
Managing
General Investor
Partner Partners
-------- --------
Interest income on capital contributions - 100%
Oil and gas sales* 11% 89%
All other revenues* 11% 89%
Organization and offering costs (1) - 100%
Syndication costs - 100%
Amortization of organization costs - 100%
Lease acquisition costs 1% 99%
Gain/loss on property disposition* 11% 89%
Operating and administrative costs*(2) 11% 89%
Depreciation, depletion and amortization
of oil and gas properties - 100%
Intangible drilling and development costs - 100%
All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150%
of their capital contributions, the allocation will change to 15%
Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% of initial capital
contributions will be paid by the Managing General Partner and will be
treated as a capital contribution. The Partnership paid the Managing
General Partner an amount equal to 4% of initial capital contributions
for such organization costs.
(2) Administrative costs in any year which exceed 2% of capital
contributions shall be paid by the Managing General Partner and will
be treated as a capital contribution.
2. Summary of Significant Accounting Policies
The interim financial information as of June 30, 1999, and for the
three and six months ended June 30, 1999, is unaudited. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted in this Form 10-Q pursuant
to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the audited financial
statements for the year ended December 31, 1998.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Developmental Drilling Fund 91-A, L.P. was organized as a
Delaware limited partnership on January 7, 1991. The offering of such
limited and general partner interests began September 17, 1991 as part of a
shelf offering registered under the name Southwest Developmental Drilling
Program 1991-92. Minimum capital requirements for the partnership were met
on April 22, 1992, with the offering of limited and general partner
interests concluding April 30, 1992, with total investor partner
contributions of $1,144,500. The Managing General Partner made a
contribution to the capital of the Partnership at the conclusion of its
offering period in an amount equal to 1% of its net capital contributions.
The Managing General Partner's contribution was $9,800. The total capital
contributions are $1,154,300.
The Partnership was formed to engage primarily in the business of drilling
developmental and exploratory wells, to produce and market crude oil and
natural gas produced from such properties, to distribute any net proceeds
from operations to the general and investor partners and to the extent
necessary, acquire leases which contain drilling prospects. Net revenues
will not be reinvested in other revenue producing assets except to the
extent that performance of remedial work is needed to improve a well's
producing capabilities. The economic life of the Partnership thus depends
on the period over which the Partnership's oil and gas reserves are
economically recoverable.
The Partnership has expended its capital and acquired leasehold interests
and completed drilling operations. Increases or decreases in Partnership
revenues and, therefore, distributions to partners will depend primarily on
changes in the prices received for production, changes in volumes of
production sold, increases and decreases in lease operating expenses,
enhanced recovery projects, offset drilling activities pursuant to farm-out
arrangements, sales of properties, and the depletion of wells. Since wells
deplete over time, production can generally be expected to decline from
year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management does not anticipate performing
workovers. The Partnership could possibly experience a normal decline.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
involved.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
Should the net capitalized costs exceed the estimated present value of oil
and gas reserves, discounted at 10%, such excess costs would be charged to
current expense. As of June 30, 1999, the net capitalized costs did not
exceed the estimated present value of oil and gas reserves. The oil price
environment experienced during 1998 had an adverse affect on the Company's
revenues and operating cash flow. Further declines of oil prices during
1999 could result in additional decreases in the carrying value of the
Company's oil and gas properties.
<PAGE>
Results of Operations
A. General Comparison of the Quarters Ended June 30, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended June 30, 1999 and 1998:
Three Months
Ended Percentage
June 30, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 15.97 13.32 20%
Average price per mcf of gas $ 1.79 1.24 44%
Oil production in barrels 2,450 2,800 (13%)
Gas production in mcf 4,400 4,100 7%
Gross oil and gas revenue $ 45,273 42,382 7%
Net oil and gas revenue $ 27,543 11,126 148%
Partnership distributions $ - 11,500 (100%)
Investor partner distributions $ - 10,235 (100%)
Per unit distribution to investor
partners $ - 8.94 (100%)
Number of investor partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues increased to $45,273 from $42,382
for the quarters ended June 30, 1999 and 1998, respectively, an increase of
7%. The principal factors affecting the comparison of the quarters ended
June 30, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended June 30, 1999 as compared to the
quarter ended June 30, 1998 by 20%, or $2.65 per barrel, resulting in
an increase of approximately $7,400 in revenues. Oil sales represented
83% of total oil and gas sales during the quarter ended June 30, 1999
as compared to 88% during the quarter ended June 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 44%, or $.55 per mcf, resulting in
an increase of approximately $2,300 in revenues.
The total increase in revenues due to the change in prices received
from oil and gas production is approximately $9,700. The market price
for oil and gas has been extremely volatile over the past decade, and
management expects a certain amount of volatility to continue in the
foreseeable future.
<PAGE>
2. Oil production decreased approximately 350 barrels or 13% during the
quarter ended June 30, 1999 as compared to the quarter ended June 30,
1998, resulting in a decrease of approximately $5,600 in revenues.
Gas production increased approximately 300 mcf or 7% during the same
period, resulting in an increase of approximately $500 in revenues.
The net total decrease in revenues due to the change in production is
approximately $5,100. Production continues on a steady decline.
Costs and Expenses
Total costs and expenses decreased to $26,757 from $48,986 for the quarters
ended June 30, 1999 and 1998, respectively, a decrease of 45%. The
decrease is the result of lower lease operating costs, depletion expense
and general and administrative expense.
1. Lease operating costs and production taxes were 43% lower, or
approximately $13,500 less during the quarter ended June 30, 1999 as
compared to the quarter ended June 30, 1998. The decline in lease
operating costs is primarily in relation to the drop in oil prices
experienced throughout 1998 and into the first six months of 1999,
which made it uneconomical to perform workovers necessary to increase
production and perform major repairs thus making it necessary to shut-
in some wells.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
23% or approximately $1,300 during the quarter ended June 30, 1999 as
compared to the quarter ended June 30, 1998. The decrease of general
and administrative costs were in part due to additional accounting
costs incurred in 1998 in relation to the outsourcing of K-1 tax
package preparation; a change in auditors requiring opinions from both
the predecessors and successor auditors and a new accounting
pronouncement requiring review by the independent auditors of the 10-
Q's. The Managing General Partner has also made an effort to cut back
on general and administrative costs whenever and wherever possible.
3. Depletion expense decreased to $4,600 for the quarter ended June 30,
1999 from $12,000 for the same period in 1998. This represents a
decrease of 62%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. Contributing
factors to the decline in depletion expense between the comparative
periods were the increase in the price of oil and gas used to determine
the Partnership's reserves for April 1, 1999 as compared to 1998 and
the decrease in gross oil and gas revenues.
<PAGE>
B. General Comparison of the Six Month Periods Ended June 30, 1999 and
1998
The following table provides certain information regarding performance
factors for the six month periods ended June 30, 1999 and 1998:
Six Months
Ended Percentage
June 30, Increase
1999 1998 (Decrease)
---- ---- ----------
Average price per barrel of oil $ 13.65 13.59 -
Average price per mcf of gas $ 1.58 1.63 (3%)
Oil production in barrels 5,180 5,700 (9%)
Gas production in mcf 8,700 9,300 (6%)
Gross oil and gas revenue $ 84,444 92,616 (9%)
Net oil and gas revenue $ 49,379 42,849 15%
Partnership distributions $ 20,000 20,000 -
Investor partner distributions $ 17,800 17,800 -
Per unit distribution to investor
partners $ 15.55 15.55 -
Number of investor partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $84,444 from $92,616
for the six months ended June 30, 1999 and 1998, respectively, a decrease
of 9%. The principal factors affecting the comparison of the six months
ended June 30, 1999 and 1998 are as follows:
1. The average price for a barrel of oil received by the Partnership
increased during the six months ended June 30, 1999 as compared to the
six months ended June 30, 1998 by less than 1%, or $.06 per barrel,
resulting in an increase of approximately $300 in revenues. Oil sales
represented 84% of total oil and gas sales during the six months ended
June 30, 1999 as compared to 84% during the six months ended June 30,
1998.
The average price for an mcf of gas received by the Partnership
decreased during the same period by 3%, or $.05 per mcf, resulting in a
decrease of approximately $500 in revenues.
The net total decrease in revenues due to the change in prices received
from oil and gas production is approximately $200. The market price
for oil and gas has been extremely volatile over the past decade, and
management expects a certain amount of volatility to continue in the
foreseeable future.
<PAGE>
2. Oil production decreased approximately 520 barrels or 9% during the six
months ended June 30, 1999 as compared to the six months ended June 30,
1998, resulting in a decrease of approximately $7,100 in revenues.
Gas production decreased approximately 600 mcf or 6% during the same
period, resulting in a decrease of approximately $900 in revenues.
The total decrease in revenues due to the change in production is
approximately $8,000. Production continues on a steady decline.
Costs and Expenses
Total costs and expenses decreased to $55,594 from $89,067 for the six
months ended June 30, 1999 and 1998, respectively, a decrease of 38%. The
decrease is primarily the result of lower lease operating costs, depletion
expense and general and administrative expense.
1. Lease operating costs and production taxes were 30% lower, or
approximately $14,700 less during the six months ended June 30, 1999 as
compared to the six months ended June 30, 1998. The decline in lease
operating costs is primarily in relation to the drop in oil prices
experienced throughout 1998 and into the first six months of 1999,
which made it uneconomical to perform workovers necessary to increase
production and perform major repairs thus making it necessary to shut-
in some wells.
2. General and administrative costs consist of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
42% or approximately $6,400 during the six months ended June 30, 1999
as compared to the six months ended June 30, 1998. The decrease of
general and administrative costs were in part due to additional
accounting costs incurred in 1998 in relation to the outsourcing of K-1
tax package preparation; a change in auditors requiring opinions from
both the predecessors and successor auditors and a new accounting
pronouncement requiring review by the independent auditors of the 10-
Q's. The Managing General Partner has also made an effort to cut back
on general and administrative costs whenever and wherever possible.
3. Depletion expense decreased to $11,600 for the six months ended June
30, 1999 from $24,000 for the same period in 1998. This represents a
decrease of 52%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. Contributing
factors to the decline in depletion expense between the comparative
periods were the increase in the price of oil and gas used to determine
the Partnership's reserves for April 1, 1999 as compared to 1998 and
the decrease in gross oil and gas revenues.
<PAGE>
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $20,500 in
the six months ended June 30, 1999 as compared to approximately $40,900 in
the six months ended June 30, 1998. The primary source of the 1999 cash
flow from operating activities was profitable operations.
Cash flows used in investing activities were approximately $800 in the six
months ended June 30, 1999 as compared to approximately $20,700 in the six
months ended June 30, 1998. The principle use of the 1999 cash flow used
in investing activities was the additions to oil and gas properties.
Cash flows used in financing activities were approximately $22,100 in the
six months ended June 30, 1999 as compared to approximately $17,900 in the
six months ended June 30, 1998. The only use in financing activities was
the distributions to partners.
Total distributions during the six months ended June 30, 1999 were $20,000
of which $17,800 was distributed to the investor partners and $2,200 to the
Managing General Partner. The per unit distribution to investor partners
during the six months ended June 30, 1999 was $15.55. Total distributions
during the six months ended June 30, 1998 were $20,000 of which $17,800 was
distributed to the investor partners and $2,200 to the Managing General
Partner. The per unit distribution to investor partners during the six
months ended June 30, 1998 was $15.55.
The source for the 1999 distributions of $20,000 was oil and gas operations
of approximately $20,500, partially offset by the addition to oil and gas
properties of approximately $800, with the balance from available cash on
hand at the beginning of the period. The source for the 1998 distributions
of $20,000 was oil and gas operations of approximately $40,900, partially
offset by the addition to oil and gas properties of approximately $20,700.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,147,740 have been made to the partners. As of June 30, 1999,
$1,023,400 or $894.19 per investor partner unit has been distributed to the
investor partners, representing a 89% return of the capital contributed.
As of June 30, 1999, the Partnership had approximately $28,000 in working
capital. The Managing General Partner knows of no unusual contractual
commitments and believes the revenues generated from operations are
adequate to meet the needs of the Partnership.
<PAGE>
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due in 1999 on its debt
obligations. Due to severely depressed commodity prices, the Managing
General Partner is experiencing difficulty in generating sufficient cash
flow to meet its obligations and sustain its operations. The Managing
General Partner is currently in the process of renegotiating the terms of
its various obligations with its creditors and/or attempting to seek new
lenders or equity investors. Additionally, the Managing General Partner
would consider disposing of certain assets in order to meet its
obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will agree to
a course of action consistent with the Managing General Partners
requirements in restructuring the obligations. Even if such agreement is
reached, it may require approval of additional lenders, which is not
assured. Furthermore, there can be no assurance that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Under current circumstances, the Managing General
Partner's ability to continue as a going concern depends upon its ability
to (1) successfully restructure its obligations or obtain additional
financing as may be required, (2) maintain compliance with all debt
covenants, (3) generate sufficient cash flow to meet its obligations on a
timely basis, and (4) achieve satisfactory levels of future earnings. If
the Managing General Partner is unsuccessful in its efforts, it may be
unable to meet its obligations making it necessary to undertake such other
actions as may be appropriate to preserve asset values.
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner is continuing in its effort to
identify and assess its exposure to the potential Year 2000 software and
imbedded chip processing and date sensitivity issue. Through the Managing
General Partners data processing subsidiary, Midland Southwest Software,
Inc., the Managing General Partner proactively initiated a plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.
Identification & Assessment
The Managing General Partner currently believes it has identified the
internal and external software and hardware that may have date sensitivity
problems. Four critical systems and/or functions were identified: (1) the
proprietary software of the Partnership (OGAS) that is used for oil & gas
property management and financial accounting functions, (2) the DEC VAX/VMS
hardware and operating system, (3) various third-party application software
including lease economic analysis, fixed asset management, geological
applications, and payroll/human resource programs, and (4) External Agents.
The proprietary software of the Partnership is currently in process of
meeting compliance requirements with an estimated completion date of mid-
year 1999. Since this is an internally generated software package, the
Managing General Partner has estimated the cost to be approximately $25,000
by estimating the necessary man-hours. These modifications are being made
by internal staff and do not represent additional costs to the Partnership.
The Managing General Partner has not made contingency plans at this time
since the conversion is ahead of schedule and being handled by Managing
General Partner controlled internal programmers. Given the complexity of
the systems being modified, it is anticipated that some problems may arise,
but with an expected early completion date, the Managing General Partner
feels that adequate time is available to overcome unforeseen delays.
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It will be installed in
August 1999, the Managing General Partner believes that this will solve any
potential problems on the system.
<PAGE>
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is working with the vendors to
secure solutions as well as prepare contingency plans. After review and
evaluation of the vendor plans and status, the Managing General Partner
believes that the problems will be resolved prior to the year 2000 or the
alternate contingency plan will sufficiently and adequately remediate the
problem so that there is no material disruption to business functions.
The External Agents of the Partnership include suppliers, customers,
owners, vendors, banks, product purchasers including pipelines, and other
oil and gas property operators. The Managing General Partner is in the
process of identifying and communicating with each critical External Agent
about its plan and progress thereof in addressing the Year 2000 issue.
This process is on schedule and the Managing General Partner, at this time,
believes that there should be no material interference or disruption
associated with any of the critical External Agent's functions necessary to
the Partnership's business. The Managing General Partner estimates
completion of this audit by mid-year 1999 and believes that alternate plans
can be devised to circumvent any material problems arising from critical
External Agent noncompliance.
Cost
To date, the Managing General Partner has incurred only minimal internal
man-hour costs for identification, planning, and maintenance. The Managing
General Partner believes that the necessary additional costs will also be
minimal and most will fall under normal and general maintenance procedures
and updates. An accurate cost cannot be determined at this time, but it is
expected that the total cost to remediate all systems to be less than
$50,000.
Risks/Contingency
The failure to correct critical systems of the Partnership, or the failure
of a material business partner or External Agent to resolve critical Year
2000 issues could have a serious adverse impact on the ability of the
Partnership to continue operations and meet obligations. Based on the
Managing General Partner's evaluation and assessment to date, it is
believed that any interruption in operation will be minor and short-lived
and pose no material monetary loss, safety, or environmental risk to the
Partnership. However, until all assessment is complete, it is impossible
to accurately identify the risks, quantify potential impacts or establish a
final contingency plan. The Managing General Partner believes that its
assessment and contingency planning will be complete no later than mid-year
1999.
Worst Case Scenario
The Securities and Exchange Commission requires that public companies must
forecast the most reasonably likely worst case Year 2000 scenario, assuming
that the Managing General Partner's Year 2000 plan is not effective.
Analysis of the most reasonably likely worst case Year 2000 scenarios the
Partnership may face leads to contemplation of the following possibilities
which, though considered highly unlikely, must be included in any
consideration of worst cases: widespread failure of electrical, gas, and
similar supplies by utilities serving the Partnership; widespread
disruption of the services of communications common carriers; similar
disruption to means and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers; significant disruption to
the Partnership's ability to gain access to, and continue working in,
office buildings and other facilities; and the failure, of third-parties
systems, the effects of which would have a cumulative material adverse
impact on the Partnership's critical systems. The Partnership could
experience an inability by customers, traders, and others to pay, on a
timely basis or at all, obligations owed to the Partnership. Under these
circumstances, the adverse effect on the Partnership, and the diminution of
Partnership revenues, could be material, although not quantifiable at this
time.
<PAGE>
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
27 Financial Data Schedule
(b) Reports on Form 8-K:
No reports on Form 8-
K were filed during the quarter ended June 30, 1999.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHWEST DEVELOPMENTAL
DRILLING FUND 91-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
Bill E. Coggin, Vice
President
and Chief Financial Officer
Date: August 15, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Balance Sheet at June 30, 1999 (Unaudited) and the Statement of Operations
for the Six Months Ended June 30, 1999 (Unaudited) and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 8,278
<SECURITIES> 0
<RECEIVABLES> 20,274
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 28,552
<PP&E> 1,098,374
<DEPRECIATION> 924,600
<TOTAL-ASSETS> 202,326
<CURRENT-LIABILITIES> 522
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 201,804
<TOTAL-LIABILITY-AND-EQUITY> 202,326
<SALES> 84,444
<TOTAL-REVENUES> 84,500
<CGS> 35,065
<TOTAL-COSTS> 35,065
<OTHER-EXPENSES> 20,529
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 28,906
<INCOME-TAX> 0
<INCOME-CONTINUING> 28,906
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 28,906
<EPS-BASIC> 21.36
<EPS-DILUTED> 21.36
</TABLE>
